In-situ formation strength testing with formation sampling

ABSTRACT

A method and apparatus for estimating a property include evaluating a formation at a formation evaluation location using a formation evaluation tool, and estimating the property at least in part by engaging a borehole wall substantially adjacent the formation evaluation location with a formation strength test device.

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a non-provisional application of U.S. provisional application 60/990,521 filed on Nov. 27, 2007, the entire specification being hereby incorporated herein by reference.

BACKGROUND

1. Technical Field

The present disclosure generally relates to wellbore tools and in particular to methods and apparatus for estimating formation properties.

2. Background Information

Oil and gas wells have been drilled at depths ranging from a few thousand feet to as deep as five miles. A large portion of the current drilling activity involves directional drilling that includes drilling boreholes deviated from vertical by a few degrees to horizontal boreholes, to increase the hydrocarbon production from earth formations.

Information about the subterranean formations traversed by the borehole may be obtained by any number of techniques. Techniques used to obtain formation information include obtaining one or more core samples of the subterranean formations and obtaining fluid samples produced from the subterranean formations these samplings are collectively referred to herein as formation sampling. Core samples are often retrieved from the borehole and tested in a rig-site or remote laboratory to determine properties of the core sample, which properties are used to estimate formation properties. Modern fluid sampling includes various downhole tests and sometimes fluid samples are retrieved for surface laboratory testing.

Laboratory tests suffer in that in-situ conditions must be recreated using laboratory test fixtures in order to obtain meaningful test results. These recreated conditions may not accurately reflect actual in-situ conditions and the core and fluid samples may have undergone irreversible changes in transit from the downhole location to the surface laboratory. Furthermore, downhole fluid tests do not provide information relating to formation direction and other rock properties.

SUMMARY

The following presents a general summary of several aspects of the disclosure in order to provide a basic understanding of at least some aspects of the disclosure. This summary is not an extensive overview of the disclosure. It is not intended to identify key or critical elements of the disclosure or to delineate the scope of the claims. The following summary merely presents some concepts of the disclosure in a general form as a prelude to the more detailed description that follows.

Disclosed is an apparatus for estimating a property. The apparatus may include a formation evaluation tool conveyable to a formation evaluation location, and a formation strength test device having a member that engages a borehole wall substantially adjacent the formation evaluation location for estimating the property.

In one aspect, an apparatus for estimating a property may include a carrier conveyable in a borehole to a formation. Two or more packers may be used to isolate an annular zone about the carrier, and a formation evaluation tool may be disposed on the carrier, the formation evaluation tool adapted to evaluate the formation at a formation evaluation location. A formation strength test device may be coupled to the carrier and adapted to provide information indicative of the property, the property relating to the isolated annular zone substantially adjacent the formation evaluation location.

Also disclosed is a method for estimating a property. The method includes evaluating a formation at a formation evaluation location using a formation evaluation tool, and estimating the property at least in part by engaging a borehole wall substantially adjacent the formation evaluation location with a formation strength test device.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the several non-limiting embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:

FIG. 1 illustrates a non-limiting example of a well logging apparatus according to several embodiments of the disclosure;

FIG. 2 is a non-limiting example of a downhole tool electronics section that may be used with a well logging apparatus;

FIG. 3 represents a non-limiting example of a formation strength test device and formation sampling device that may be used in several disclosed embodiments of a well logging apparatus;

FIG. 4 illustrates an exemplary formation strength test device having articulating pistons that may be used in several disclosed embodiments of a well logging apparatus;

FIG. 5 is a nom-limiting example of a mandrel section having combined formation strength testing, fluid sampling and core sampling;

FIG. 6 is a non-limiting schematic illustration of a measurement and control circuit that may be used according to several embodiments of the present disclosure;

FIG. 7 graphically illustrates a formation core sample response to an applied force;

FIG. 8 is an exemplary stress vs. strain plot that shows core sample deformation in axial and radial directions due to an applied force; and

FIG. 9 is a non-limiting method for estimating formation strength at or near a formation sampling location.

DESCRIPTION OF EXEMPLARY EMBODIMENTS

With reference to FIG. 1, a non-limiting example of a well logging apparatus 100 according to several embodiments of the disclosure will be described. The well logging apparatus 100 is shown disposed in a well borehole 102 penetrating earth formations 104 for making measurements of properties of the earth formations 104. The borehole 102 is typically filled with a fluid having a density sufficient to prevent formation fluid influx.

A string of logging tools, or simply, tool string 106 is shown lowered into the well borehole 102 by an armored electrical cable 108. The cable 108 can be spooled and unspooled from a winch or drum 110. The tool string 106 may be configured to convey information signals to surface equipment 112 by an electrical conductor and/or an optical fiber (not shown) forming part of the cable 108. The surface equipment 112 can include one part of a telemetry system 114 for communicating control signals and data signals to the tool string 106 and may further include a computer 116. The computer can also include a data recorder 118 for recording measurements made by the tool string 106 sensors and transmitted to the surface equipment 112.

The exemplary tool string 106 may be centered within the well borehole 102 by a top centralizer 120 a and a bottom centralizer 120 b attached to the tool string 106 at axially spaced apart locations. The centralizers 120 a, 120 b can be of types known in the art such as bowsprings or inflatable packers. In other non-limiting examples, the tool string 106 may be forced to a side of the borehole 102 using one or more extendable members.

The tool string 106 of FIG. 1 illustrates a non-limiting example of an in-situ formation strength test tool in combination with one or more formation evaluation tools, along with several examples of supporting functions that may be included on the tool string 106. The tool string 106 in this example is a carrier for conveying several sections of the tool string 106 into the well borehole 102. The tool string 106 includes an electrical power section 122 and an electronics section 124 is coupled to the electrical power section 122. A mechanical power section 126 is disposed on the tool string 106 and is coupled in this example to the electronics section 124. A mandrel section 128 is shown disposed on the tool string 106 below the mechanical power section 126 and the mandrel section 128 includes a formation strength test device 130 and a formation evaluation tool 138 that may include a formation sampling tool, a formation test tool or a combination thereof.

The electrical power section 122 receives or generates, depending on the particular tool configuration, electrical power for the tool string 106. In the case of a wireline configuration as shown in this example, the electrical power section 122 may include a power swivel that is connected to the wireline power cable 108. In the case of a while-drilling tool, the electrical power section 122 may include a power generating device such as a mud turbine generator, a battery module or other suitable downhole electrical power generating device. In some examples wireline tools may include power generating devices and while-drilling tools may utilize wired pipes for receiving electrical power and communication signals from the surface. The electrical power section 122 may be electrically coupled to any number of downhole tools and to any of the components in the tool string 106 requiring electrical power. The electrical power section 122 in the example shown provides electrical power to the electronics section 124.

With reference to FIGS. 1 and 2, the electronics section 124 may include any number of electrical components for facilitating downhole tests, information processing and/or storage. In some non-limiting examples, the electronics section 124 includes a processing system 200 that includes at least one information processor 202. The processing system 200 may be any suitable processor-based control system suitable for downhole applications and may utilize several processors depending on how many other processor-based applications are to be included in the tool string 106. Some electronic components may include added cooling, radiation hardening, vibration and impact protection, potting and other packaging details that do not require in-depth discussion here. Processor manufacturers that produce processors 202 suitable for downhole applications include Intel, Motorola, AMD, Toshiba and others.

In wireline applications, the electronics section 124 may be limited to transmitter and receiver circuits to convey information to a surface controller and to receive information from the surface controller via a wireline communication cable. In the example shown, the processor system 200 further includes a memory unit 204 for storing programs and information processed using the processor 202. Transmitter and receiver circuits 206 are included for transmitting and receiving information to and from the tool string 106. Signal conditioning circuits 208 and any other electrical component suitable for the tool string 106 may be housed within the electronics section 124. A power bus 210 may be used to communicate electrical power from the electrical power section 122 to the several components and circuits housed within the electronics section 124. A data bus 212 may be used to communicate information between the mandrel section 128 and the processing system 200 and between the processing system 200 and the surface computer 116 and recorder 118. The electrical power section 122 and electronics section 124 may be used to provide power and control information to the mechanical power section 126 where the mechanical power section 126 includes electro-mechanical devices.

In the non-limiting example of FIG. 1, the mechanical power section 126 may be configured to include any number of power generating devices 136 to provide mechanical power to the formation strength test device 130. The power generating device or devices 136 may include one or more of a hydraulic unit, a mechanical power unit, an electro-mechanical power unit or any other unit suitable for generating mechanical power for the mandrel section 128 and other not-shown devices requiring mechanical power.

In several non-limiting examples, the mandrel section 128 may utilize mechanical power from the mechanical power section 126 and may also receive electrical power from the electrical power section 126. Control of the mandrel section 128 and of devices on the mandrel section 128 may be provided by the electronics section 124 or by a controller disposed on the mandrel section 128. In some embodiments, the power and control may be used for orienting the mandrel section 128 within the well borehole. The mandrel section 128 can be configured as a rotating sub that rotates about and with respect to the longitudinal axis of the tool string 106. Bearing couplings 132 and drive mechanism 134 may be used to rotate the mandrel section 128. In other examples, the mandrel section 128 may be oriented by rotating the tool string 106 and mandrel section 128 together. The electrical power from the electrical power section 122, control electronics in the electronics section 124, and mechanical power from the mechanical power section 126 may be in communication with the mandrel section 128 to power and control the formation strength test device 130 and with the formation sampling and test tool 138.

Referring now to FIGS. 1 and 3, the formation strength test device 130 of the present disclosure may include one or more extendable pistons. In the example of FIG. 3, the formation strength test device includes extendable pistons 300, 302, 304 that may receive mechanical power from the mechanical power section 126 via a power transfer medium 306 coupled to the power generating device 136 and selected according to the particular power generating devices 136 used. For example, the power transfer medium 306 may be a hydraulic fluid conduit where the power generating device 136 includes a hydraulic pump, the power transfer medium 306 may be an electrical conductor where the power generating device 136 includes an electrical power generator, and the power transfer medium 306 may be a drive shaft or gearbox where the power generating device 136 includes a mechanical power output for extending the pistons 300, 302, 304. Each of the extendable pistons 300, 302, 304 may have a corresponding housing 308 that includes hydraulic, or mechanical assemblies used to extend the respective piston 300, 302, 304. The one or more extendable pistons 300, 302, 304 may be extended from the mandrel section 128 to engage the borehole wall with sufficient force to determine properties of the formation. In several examples the force may be selected to deform or break the formation at or near the piston-formation interface.

Each of the pistons in the example shown includes a wall-engaging end 310, 312, 314 having a predetermined surface shape and area. The exemplary formation strength test device 130 includes one piston 300 having a wall-engaging end 310 that has large surface area with at least one radius of curvature about equal to the borehole radius. A second of the extendable pistons 302 includes a wall-engaging end 312 with a surface area that is smaller than the end of the first piston 300, and the third of the extendable pistons 304 includes a wall-engaging end 314 with a surface area that is smaller than either of the first and second pistons. The end of the third piston 304 may include a pointed or chisel-shaped end to increase the force per unit area. Information relating to the speed of extension, force applied by the respective piston, distance of piston travel and the like may be monitored by suitable sensors 316 associated with the respective piston. Information measured by the sensors 316 may be transmitted to the electronics section 124 via the data bus 212 for processing.

Continuing now with the exemplary tool of FIG. 3, a formation evaluation tool 138 is shown coupled to the mandrel 128 below the formation strength test device 130. The relative positioning is not critical, and in some cases the tool string 106 may include two separate mandrels 128 with the formation strength test device 130 being disposed on one mandrel and the formation evaluation tool 138 being disposed on the second mandrel coupled to the first mandrel 128 using a suitable coupling 318. The formation evaluation tool 138 may be any tool 140 capable of retrieving a sample of the formation 104 adjacent the tool string 106. In one embodiment, the formation evaluation tool 138 may include a formation fluid sampling tool, a coring tool, a resistivity tool, a nuclear magnetic resonance tool, or any other suitable formation evaluation tool. In another embodiment, the formation evaluation tool 138 may include a formation fluid sampling tool and a coring tool. In several embodiments, the formation evaluation tool 138 includes an extendable formation fluid sampling probe 140 that is extendable to engage the formation 104 and to form a sealed fluid communication pathway from the formation to the tool 138. In several non-limiting embodiments, the formation evaluation tool may include one or more fluid sample chambers 142 for receiving and storing fluid sampled from the formation 104. Fluid may be directed to a selected chamber 142 by the use of one or more valves 144 coupled to a fluid conduit 146. Each sampling chamber 142 may include an associated pressure control device 148 for maintaining the sample chamber pressure at a pressure substantially equal to the formation pressure at the sampling location. Each pressure control device 148 may be controlled by the downhole processor system 200 and mechanically or hydraulically by the mechanical power section 126 via the power transfer medium 306. Several examples of suitable sampling chamber configurations capable of maintaining sample pressure are described in U.S. Pat. Nos. 5,303,775 and 5,377,755 for “Method and Apparatus for Acquiring and Processing Subsurface Samples of Connate Fluid,” which patents are assigned to the assignee of the present application and incorporated herein in their entireties by reference.

The formation evaluation tool 138 may further include one or more fluid test devices 150 to test fluid samples received by the formation evaluation tool 138. The test devices 150 may include any number of transducers 152 and sensors for measuring characteristics of the fluid received by the tool. Non-limiting examples of suitable transducers 152 include optical sensors, NMR sensors, acoustic sensors, resistivity sensors, capacitance sensors, pressure sensors, temperature sensors, and any other transducer useful in characterizing fluid sampled by the tool 138. Furthermore, one or more of the transducers 152 may be associated with the fluid conduit leading from the extendable probe 140 to measure fluid characteristics of fluid in the conduit prior to directing the fluid to the chambers 142. In this manner and using not-shown conduits leading back to the borehole 102, fluid entering the probe 140 may be flushed until the fluid in the conduit leading to the chambers is substantially free of borehole fluid. Determination of fluid content may be accomplished by transmitting output signals from the transducers 152 to a suitable processor for estimating fluid content. In several examples, downhole signal processing may be accomplished using the electronics section 124 of the tool string 106. The electronics section 124 may include a downhole spectrometer that receives signals from optical sensors in the formation evaluation tool 138 to determine fluid content. Formation properties estimated based on the fluid content measurements may be further enhanced by an understanding of formation property measurements taken in several directions, which may be accomplished using articulated strength measurement pistons.

The formation strength test device 130 described above and shown in the exemplary views may include one or more articulated piston assemblies to move the respective pistons 300, 302, 304 in several angular directions with respect to the mandrel 128 longitudinal axis. Referring to FIG. 4, the mandrel 128 may include one or more extendable pistons 300, 302, 304 substantially as described above and shown in FIG. 3. Each piston 300, 302, 304 may be movably coupled to the mandrel 128 in a moveable relationship using a coupling 400 that allows articulated movement with at least one degree of freedom to engage the formation 104 at a desired angle of engagement. Each piston may be retracted and extended two or more times with the angle of engagement adjusted for each extension to obtain formation property information that is associated with each angle of engagement. This information may be used in estimating directional properties of the formation at the formation-borehole interface. The angle of engagement can be determined in part by the tool angular position with respect to vertical and/or the borehole. In several examples, tool angle and borehole angle may be substantially the same, and in other examples the tool may be angularly displaced within the borehole. In each case the tool angle may be determined using magnetometers, accelerometers and/or other suitable sensors 320 to determine the tool orientation and angle in real time. The angle of engagement can also be determined in part by the formation boundary angle with respect to vertical and/or the borehole or by a combination of the tool angle and the formation boundary angle. The formation boundary angle can be estimated from preexisting seismic information or by formation pressure tests designed to determine in real time the upper and lower formation boundaries at the borehole-formation intersection.

Continuing with FIG. 4, the coupling 400 may be, for example, a ball-joint coupling, a pivot pin coupling, a rail coupling, a rack and pinion coupling or the like. Each coupling may be controllably manipulated using commands generated from the surface by an operator or by the surface computer 116. In other embodiments the couplings may be controllably manipulated using commands generated by the downhole processing system 200 of FIG. 2. Shown schematically in FIG. 4 are rack and pinion type couplings with the pinion being rotated by a suitable drive device that receives control signals via the power medium 306 described above and shown in FIG. 3. Likewise, the commanding information may be received at each coupling via the data bus 212 where the couplings are suited for receiving control signals. One example of such data bus control may include couplings having individual electrical stepper motors with on-board controllers. A position command may be sent to each motor independently such that the associated stepper motor may position the angle of the respective piston as desired. Individual positioning may alternatively be accomplished using individual hydraulic pumps and reservoirs or by using controllable valves to position each piston as desired. Whether the particular piston is configured for articulated angular motion or for unarticulated linear movement, the force applied to the formation location engaged by the piston and the piston wall-engaging surface characteristics may be known and/or measured to determine parameters at or near the sampling location that are indicative of formation properties at or near the formation sampling location.

Referring now to FIG. 5, an exemplary mandrel 128 according to one or more embodiments may include a combination of formation strength test and sampling tools disposed between straddle packers. The exemplary mandrel 128 shown in FIG. 5 includes upper and lower packers 502. Disposed between the upper and lower packers 502 are a formation fluid sampling tool 504, a formation strength test device 130 disposed on the mandrel 128 proximate the formation fluid sampling tool 504, and a rotary sidewall coring tool 506 disposed on the mandrel 128 proximate the formation fluid sampling device 138 and the formation strength test device 130. Fluid sampling chambers 142 may be disposed on the mandrel 128 near the formation fluid sampling tool 504, but the sampling chambers 142 need not be located between the packers 502. Decentralizing members 508 may be used to move the strength test device 130 and/or the coring tool 506 toward respective borehole wall locations. The coring tool 506 may be any sidewall rotary coring tool. In several exemplary embodiments, the coring tool 506 may be substantially as described in U.S. Pat. No. 5,617,927 for “Sidewall Rotary Coring Tool” and in published U.S. patent application Ser. No. 11/215,271 having the publication number US 2007/0045005 A2, which patent and published application are assigned to the assignee of the present application. Core samples may be stored within the mandrel 128 in a core sample chamber 510. The core sample chamber 510 may be in fluid communication with the formation fluid sampling tool 504 to allow for storing formation core samples in pristine formation fluid. The core sample chamber 510 may also include a pressure control device 148 substantially as described above and shown in FIG. 3 to maintain the core sample chamber 510 at substantially the same pressure as the formation core sampling location for transport to the surface. The upper and lower packers 502 may be used to form an annular region for conducting the several formation tests and sampling disclosed herein in an isolated zone between the packers 502.

In several non-limiting embodiments, the packers 502 selectively expand to isolate the annular section between the packers 502. The packers 502 may be actuated by any number of actuating mechanisms. The packers may be actuated using pressurized hydraulic fluid received via the power transfer medium 306 leading from the mechanical power section 126. In other embodiments, the packers 502 may be mechanically compressed or actuated using hydraulically actuated pistons or the like. When actuated, each packer element 502 expands and sealingly engages an adjacent borehole wall area to form a fluid barrier across an annulus portion of the borehole 102. In one example, the packers 502 include flexible bladders that can deform sufficiently to maintain a sealing engagement with the formation 104 even though the mandrel 128 may not be centrally positioned in the borehole 102. The packers 502, when actuated, provide the isolated zone that reduces or prevents fluid movement into or out of the isolated zone between the packers 502.

It will be appreciated from the present disclosure that isolating a zone along the wellbore axis increases the likelihood that formation fluid can be efficiently extracted from a formation. For instance, a wellbore wall may include laminated areas that block fluid flow or fractures that prevent an effective seal from being formed by a pad pressed on the borehole wall. An isolated axial zone when used with or without an additional extendable sampling probe having a sealing pad provides a greater likelihood that a region or area having favorable flow characteristics will be captured. Thus, laminated areas or fractures will be less likely to interfere with fluid sampling. Moreover, the formation could have low permeability, which restricts the flow of fluid out of the formation. Utilizing an isolated zone can increase the flow rate of fluid into the zone and therefore reduce the time needed to obtain a pristine fluid sample. The formation fluid sampling tool 504 may include a pump that can cause the isolated zone between the packers 502 to have an environmental condition different that the environment of the regions above and below the isolated zone. In several examples, the different environmental condition may include a different pressure and/or a different fluid content.

FIG. 6 is a schematic illustration of a measurement and control circuit 600 that may be used according to the present disclosure. The measurement and control circuit 600 includes one or more angular position sensors 602, force sensors 604, and displacement sensors 606 that may be used with the formation strength test device 130 estimate formation parameters such as angle α, piston force F_(P), and piston extension X for each of the extendable pistons 300, 302, 304. The sensors 602, 604, and 606 may be coupled to transmit sensor output signals to respective signal conditioning circuits 608 for filtering the signals as needed. The signal conditioning circuits 608 may be coupled to transmit conditioned signals to an analog-to-digital converter (ADC) circuit 610 where any of the sensors does not provide a digital output signal. ADC circuit 610 output signals may be fed into a multiplexer circuit 612 or into a multi-channel input of a processor 614. The processor 614 may then feed processed signals to a memory 616 and/or to a transceiver circuit 920. The processor 916 may be located on the tool string 106 as noted above or may be a surface processor such as the processor 116 described above and shown in FIG. 1. When using a downhole processor, commands may be received via the transceiver circuit 618. Downhole command and control of the tool string 106 and of the pistons may be accomplished using programmed instructions stored in the memory 616 or other computer-readable media that are then accessed by the processor 614 and used to conduct the several methods and downhole operations disclosed herein. The information obtained from the sensors may be processed down-hole using the electronics section 124 with the processed information being stored downhole in the memory 616 for later retrieval. In other embodiments, the processed information may be transmitted to the surface in real time in whole or in part using the transceiver 618.

Downhole tools such as those described above and shown in FIGS. 1-6 or similar tools may be used to carry out methods that will now be described in detail. In the several non-limiting method examples to follow, one or more formation properties may be estimated using in-situ formation strength measurements substantially adjacent a formation sampling location. A sampling location is a location within a well borehole where a formation evaluation tool engages the subterranean formation to extract a sample from the subterranean formation. Extracting a sample from a borehole wall area is becoming increasingly popular due to tools such as rotary sidewall coring devices and extendable probe fluid sampling tools. Formation properties estimated from measurements made at or near the sampling location provide valuable information obtained using actual in-situ conditions. Moreover, measurements made within a controlled isolated zone provide additional control over the test methods.

Formation properties include several components that may be measured in-situ or estimated using in-situ measurements provided by the formation strength test tool of the present disclosure. The several components of formation properties include stress, Young's modulus, Poisson's Ratio and formation unconfined compressive strength. A short discussion of these formation properties follows.

Stress on a given sample is defined as the force acting on a surface of unit area. It is the force divided by the area as the area approaches zero. Stress has the units of force divided by area, such as pounds per square inch, or psi, kilo Pascals (kilo Newtons per square meter), kPa, MPa, etc. A given amount of force acting on a smaller area results in a higher stress, and vice versa.

The Young's modulus of a rock sample is the stiffness of the formation, defined as the amount of axial load (or stress) sufficient to make the rock sample undergo a unit amount of deformation (or strain) in the direction of load application, when deformed within its elastic limit. The higher the Young's modulus, the harder it is to deform it. It is an elastic property of the material and is usually denoted by the English alphabet E having units the same as that of stress.

The Poisson's ratio of an elastic material is also its material property that describes the amount of radial expansion when subject to an axial compressive stress (or deformation measured in a direction perpendicular to the direction of loading). Poisson's ratio is the ratio of the elastic material radial deformation (strain) to its axial deformation (strain), when deformed within its elastic limit. Rocks usually have a Poisson's ratio ranging from 0.1 to 0.4. The maximum value of Poisson's ratio is 0.5 corresponding to an incompressible material (such as water). It is denoted by the Greek letter ν (nu). Since it is a ratio, it is unitless.

The Unconfined Compressive Strength (UCS) of a material is the maximum compressive stress an element of rock can take before undergoing failure. It is usually determined in the laboratory on cylindrical cores, subjected to axial compressive stress under unconfined conditions (no lateral support or confining pressure being applied on the sides). It has the same units as that of stress (force per unit area: psi, MPa, etc.).

In-situ stresses are the stresses that exist within the surface of the earth. There are three principal (major) stresses acting on any element within the surface of the earth. The three stresses are mutually perpendicular to one another and include the vertical (overburden) stress resulting from the weight of the overlying sediments (σ_(v)), the minimum horizontal stress (σ_(Hmin)) resulting from Poisson's effect, and maximum horizontal stress (σ_(Hmax)) resulting from Poisson's and tectonic/thermal effects.

FIGS. 7 and 8 illustrate a core sample test used to determine Young's modulus (E), Poisson's ratio (ν) and the unconfined compressive strength (UCS) for a free-standing cylindrical rock sample that may be accomplished using the formation strength test device 130 described herein along with the formation coring tool 506 described above and shown in FIG. 5. FIG. 7 illustrates a free-standing core sample test. A force (F) is applied to a cylindrical sample having a free end surface of diameter (D) and a core sample length (L). The core sample is fixed at a base location and is free to deform in an axial direction and in a radial direction due to the force (F) applied to yield σ₁=F/area, where σ₁ is the maximum applied axial stress on the sample. Deformation in the axial direction is noted in the figure as δ₁ and deformation in the radial direction is noted by δ₃. Using these parameters yields E, ν and UCS as follows in equations 1, 2 and 3 below.

E=δσ ₁/δε₁  Equation 1

ν=−δε₃/δε₁  Equation 2

UCS=σ_(max)  Equation 3

In these equations, ε₁=δ₁/L and ε₃=2*δ₃/D. One may use known, calculated or measured values for the force applied, the cross-section area of the sample, the length of the unstressed sample cylinder, the vertical deformation and the radial deformation to provide estimates of E, ν and UCS. These parameters provide valuable information for determining the viability of a subterranean formation for hydrocarbon production.

FIG. 8 illustrates a stress vs. strain plot of the test graphically illustrated in FIG. 7. Here, the vertical axis is stress σ₁ and the horizontal axis is the axial compression ε₁ and radial expansion ε₃ of the core sample under the load F.

FIG. 9 is a flow diagram to illustrate a non-limiting method for estimating one or more formation properties by obtaining in-situ measurements substantially adjacent a sampling location. The method 900 includes conveying a formation evaluation tool and a formation strength test tool into a well borehole to a formation of interest 902. A formation sample is extracted according to this example from the formation 904. One or more parameter measurements such as strength measurements are made at a borehole wall area substantially adjacent the formation sampling location 906. Information from the in-situ parameter measurements are processed 908 using a processor and correlated with sample location information 910. Sample location information may include any information that relates to the location at which the formation fluid or core sample is taken. For example, the sample location information may include depth, temperature, formation pressure and any other information that may be correlated with the measured parameters to obtain an estimate of the formation of interest structure, strength and production value. The correlated processed parameters and sample location information are used in several examples to estimate one or more formation properties substantially adjacent the formation sampling location 912. The estimate may then be used in determining the viability of the subterranean formation of interest for hydrocarbon production and/or structural purposes.

In one embodiment, a formation strength test device is used to obtain formation property information 906 prior to extracting a sample 904. In another example, a formation sample is extracted 904 using a sampling tool prior to conducting a formation strength test device 906. In yet another example, the formation strength test and formation sample are conducted simultaneously.

The location of the formation strength test and the location of the formation sampling are each at the formation of interest and substantially adjacent the same location. As used herein, “substantially adjacent” is used to mean respective borehole wall areas for the formation strength test and formation sampling that may be overlapping in whole or in part, may be adjacent borehole wall areas, may include areas displaced about the circumference of the borehole wall at the formation of interest, and may include areas that are displaced axially along the borehole wall. Measurements substantially adjacent a formation sample location include measurements within a tool, measurements made in or on the borehole wall, and measurements that are affected by any interaction with the formation substantially adjacent a formation sampling location.

In one embodiment, a carrier that carries the formation strength test tool and the formation evaluation tool may be adjusted or moved within the borehole to bring the formation strength test tool and the coring tool to engage the borehole wall at the selected location. In another embodiment, a carrier that carries the formation strength test tool and the coring tool may be fixed within the borehole using one or more packers, an extendable anchor or other device that will hold the carrier at a fixed location. In the example of a fixed carrier, the formation strength test tool and the formation evaluation tool may be disposed on the carrier in fixed locations to engage the borehole wall in adjacent or slightly displaced locations on the borehole wall. In other examples, the carrier may be fixed at a location with the formation strength test tool and the formation evaluation tool being disposed on the carrier in a moveable manner to allow the formation strength test tool and the coring tool to engage the borehole wall in a common location on the borehole wall.

One example of the method includes moving a coring tool to a selected borehole wall location and cutting a core in the formation of interest without dislodging the core sample from the formation. This is accomplished by using a core tool to cut into the formation and then extracting the core bit from the formation while leaving the core sample connected to the formation. With the core sample still connected to the formation, a formation strength test tool engages the core sample. A force is applied to the core sample using the formation strength test tool. Measurements are made to determine the force applied and the piston extension distance. Core sample deformation is also measured, and the in-situ measurements are used to estimate the formation properties substantially adjacent the core sample location.

In another optional embodiment, formation analysis may include sampling or testing formation strength or stress by deforming the formation, which may include fracturing or chipping the formation, to estimate formation stress in situ. One method of estimating formation stress includes evaluating the ratio of force of deformation and area over which the force is applied to the formation. Pistons can exert the force onto the formation, the pistons can be disposed in housing that is rotatable within a wellbore that pierces the formation. The pistons can rotate about the wellbore's circumference and may be oriented at difference angles with respect to the wellbore axis or with respect to a formation dip. Rotation and tilt provides for three dimensional measurements within the wellbore. Mechanically measuring formation stress yields data useful for optimizing well drilling programs, casing design, modeling/planning development, and formation set.

The present disclosure is to be taken as illustrative rather than as limiting the scope or nature of the claims below. Numerous modifications and variations will become apparent to those skilled in the art after studying the disclosure, including use of equivalent functional and/or structural substitutes for elements described herein, use of equivalent functional couplings for couplings described herein, and/or use of equivalent functional actions for actions described herein. Such insubstantial variations are to be considered within the scope of the claims below. 

1. An apparatus for estimating a property, the apparatus comprising: a formation evaluation tool conveyable to a formation evaluation location; and a formation strength test device having a member that engages a borehole wall substantially adjacent the formation evaluation location for estimating the property.
 2. An apparatus according to claim 1, wherein the formation evaluation tool is conveyable on a wireline, a while drilling sub or both.
 3. An apparatus according to claim 1 further comprising a rotatable section that is rotatable with respect to a longitudinal axis of a carrier, the member being coupled to the rotatable section.
 4. An apparatus according to claim 1 further comprising an articulated coupling that couples the member to the formation strength test device, and a positioning device that adjusts an angular position of the member with respect to a longitudinal axis of a carrier.
 5. An apparatus according to claim 1, wherein at least one of the formation evaluation tool and the member is movably disposed within a mandrel.
 6. An apparatus according to claim 1, wherein the formation evaluation tool comprises a fluid sampling tool for extracting fluid from a formation.
 7. An apparatus according to claim 6 further comprising one or more sample chambers for receiving fluid extracted from the formation.
 8. An apparatus according to claim 6 further comprising one or more sensors for estimating at least one fluid characteristic of the fluid extracted from the formation.
 9. An apparatus according to claim 1, wherein the formation evaluation tool comprises a coring tool for extracting one or more core samples from a formation.
 10. An apparatus according to claim 9 further comprising one or more sample chambers for receiving the one or more core samples extracted from the formation.
 11. An apparatus according to claim 1 further comprising at least one measurement device that includes one or more of an acoustic sensor, an optical sensor, a displacement sensor, a strain sensor, a deflection sensor, and a pressure sensor.
 12. An apparatus according to claim 1 further comprising a downhole information processor for processing information relating to formation property.
 13. An apparatus for estimating a property, the apparatus comprising: a carrier conveyable in a borehole to a formation; two or more packers to isolate an annular zone about the carrier; a formation evaluation tool disposed on the carrier, the formation evaluation tool adapted to evaluate the formation at a formation evaluation location; a formation strength test device coupled to the carrier and adapted to provide information indicative of the property, the property relating to the isolated annular zone substantially adjacent the formation evaluation location.
 14. An apparatus according to claim 13, wherein the formation evaluation tool comprises a fluid sampling tool for extracting fluid from the formation.
 15. An apparatus according to claim 14 further comprising one or more sample chambers for receiving fluid extracted from the formation.
 16. An apparatus according to claim 14 further comprising one or more sensors for estimating at least one fluid characteristic of the fluid.
 17. An apparatus according to claim 13, wherein the formation evaluation tool comprises a coring tool for extracting one or more core samples from the formation.
 18. An apparatus according to claim 17 further comprising one or more sample chambers for receiving the one or more core samples.
 19. A method for a estimating property, the method comprising: evaluating a formation at a formation evaluation location using a formation evaluation tool; and estimating the property at least in part by engaging a borehole wall substantially adjacent the formation evaluation location with a formation strength test device.
 20. A method according to claim 19, wherein the formation evaluation tool includes one or more of a coring tool and a fluid sampling tool. 